During the drilling of a wellbore, various fluids are typically used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through the wellbore to the surface. During this circulation, the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
Wellbore fluids may also be used to provide sufficient hydrostatic pressure in the well to prevent the influx and efflux of formation fluids and wellbore fluids, respectively. When the pore pressure (the pressure in the formation pore space provided by the formation fluids) exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is often maintained at a higher pressure than the pore pressure. However, when wellbore pressures are maintained above the pore pressure, the pressure exerted by the wellbore fluids may exceed the fracture resistance of the formation and fractures and induced mud losses may occur. Further, formation fractures may result in the loss of wellbore fluid that decreases the hydrostatic pressure in the wellbore to decrease, which may in turn also allow formation fluids to enter the wellbore. As a result, the formation fracture pressure may define an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, one constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients through the depth of the well.
As stated above, wellbore fluids are circulated downhole to remove rock, as well as deliver agents to combat the variety of issues described above. Fluid compositions may be water- or oil-based and may contain weighting agents, surfactants, proppants, viscosifiers, and fluid loss additives. However, for a wellbore fluid to be effective during wellbore operations, the fluid has to stay in the borehole. During drilling operations, variations in formation composition may lead to undesirable fluid loss events in which substantial amounts of wellbore fluid are lost to the formation through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole. While fluid loss is often associated with drilling applications, other fluids may experience fluid loss into the formation including wellbore fluids used in completions, drill-in operations, productions, etc. Lost circulation may occur naturally in formations that are fractured, highly permeable, porous, cavernous, or vugular.
Lost circulation may also result from induced pressure during drilling. Specifically, induced mud losses may occur when the mud weight, required for well control and to maintain a stable wellbore, exceeds the fracture resistance of the formations. A particularly challenging situation arises in depleted reservoirs, in which the drop in pore pressure effectively weakens a wellbore through permeable, potentially hydrocarbon-bearing rock formation, but neighboring or inter-bedded low permeability rocks maintain their pore pressure. This can make the drilling of certain depleted zones impossible because the mud weight needed to support the shale exceeds the fracture resistance of the sands and silts. Another unintentional method by which lost circulation can result is through the inability to remove low and high gravity solids from fluids. Without being able to remove such solids, the fluid density can increase, thereby increasing the hole pressure, and if such hole pressure exceeds the formation fracture pressure, fractures and fluid loss can result.